More than two-thirds of the Earth is covered by oceans. As the petroleum industry continues in its search for hydrocarbons, it is finding that more and more of the untapped hydrocarbon reservoirs are located beneath the oceans, in “offshore” reservoirs. A typical system used to produce hydrocarbons from offshore reservoirs comprises a host production facility located on the surface of the ocean or on land, hydrocarbon producing wells located on the ocean floor (i.e. “subsea” wells) and a system of pipes that transports the hydrocarbons from the subsea wells to the host production facility.
In the offshore application, the system of pipes that transport the hydrocarbons within this production system is made up of flowlines and risers. Flowlines are typically referred to in the industry as the portion of pipes that lie on the floor of the body of water. Risers typically refer to the portion of pipes that extend from the flowlines through the water column to the host production facility.
To maintain the production capacity of the flowlines and risers, the interior of the pipes must often be cleaned of various debris or hydrocarbon wastes that can accumulate within such pipes. During fabrication and installation of the flowlines and risers, solid particles in the form of construction debris can accumulate inside the pipes, and these solids need to be removed before starting the hydrocarbon production to ensure the solids are not carried into the production equipment on the host production facility. During production, the produced fluids will typically comprise a mixture of crude oil, gases such as methane, hydrogen sulfide and carbon dioxide, water and sometimes solids, such as sand. The solid materials entrained in the produced fluids may be deposited during “shut-ins,” i.e. production stoppages, and require removal. Also, changes in temperature, pressure and/or chemical composition along the pipes may cause the deposition of other materials, such as methane hydrates, waxes or scales, on the internal surface of the flowlines and risers. These deposits need to be periodically removed, as build-up of these materials can reduce line size and constrict flow.
The flowlines and risers must also be inspected on a periodic basis to detect potential problems that may arise in the system. For instance, the presence of corrosive components in the produced fluids, such as hydrogen sulfide and carbon dioxide, may cause corrosion in the flowlines and risers. Periodic monitoring or inspections are required to detect potential corrosion of the lines.
A common method for cleaning the interior of the risers and flowlines and performing inspections is to “pig” the system. One class of pigs is designed for line cleaning, removing wax deposits and/or other debris. The pig scrapes or dislodges the deposits and/or debris from the internal surface of the pipes. Another type of pig is the “intelligent” pig, which has the capability of inspecting the flowline-riser system, for instance, a pig that can measure the wall thickness of the lines and therefore provide data to anticipate potential corrosion problems.
For any piggable system, there must be a means of getting the pig into the system, a method of propelling the pig through the system, and a way to remove the pig from the system. A common piggable flowline system for subsea wells comprises two flowlines and two risers, which are “tied” together. A typical example of such a system is provided in FIG. 1. With this configuration, a pig is sent from the host production facility 5A down a first riser 10A, into a first flowline 30A, through a flowline, sometimes called a pigging loop, 40A connecting wells 35A and 45A, through second flowline 50A, and up through a second riser 10Z back to the host production facility 5A. In the simplest form, all the lines in the system are of constant diameter. Variations of this approach feature lines of different diameters—typically a smaller-diameter riser and flowline for carrying the pig out from the host production facility, and a larger-diameter flowline and riser for returning the pig back to the host production facility. Another variation would be for first and second flowlines 30A and 50A to connect to a manifold used to commingle the production from several wells. The pigging loop 40A can be part of the manifold.
Another common pigging approach uses a subsea pig launcher. As shown in FIG. 2, the subsea pig launcher 75 attaches to the flowline 30B near the subsea well 35B, and from there launches a pig into the flowline 30B, up through the riser 10B and to the host production facility 5B. Because the pig is launched from the ocean floor and retrieved at the surface of the ocean at the host production facility 5B, a second riser is not required. Accordingly, a single flowline 30B and a single riser 10B can be used for producing hydrocarbons from the subsea well(s), while maintaining piggability of the system. However, because the launcher is located at the ocean floor, it must initially be “loaded” with multiple pigs. In order to provide long-term pigging capabilities the launcher has to be reloaded later in field life, which typically requires intervention with a remotely-operated vehicle (POV) or a diver. Moreover, difficulty arises when in a particular instance the flowline-riser system requires the use of a different type of pig than is available in the launcher, e.g. an intelligent pig instead of a cleaning pig. Such instances also typically require the intervention of an ROV or a diver. Additional related references can be found in WO 01/71158 to Kvaerner Oilfield products AS, GB 2,028,400 to Otis Engineering Corporation, WO 01/73261 to Rockwater Limited et al., U.S. Pat. No. 4,528,041 to Rickey et al., U.S. Pat. No. 6,079,498 to Sidrim et al., GB 2,191,229 to Subsea Developments Ltd., WO 95/12464 to Norsk Hydro AS et al., and GB 2,196,716 to Seanor Engineering AS et al.
The systems described above can be effective, but can also be relatively expensive to install and operate. The two-line system shown in FIG. 1 is costly because it requires the fabrication and installation of two separate risers and flowlines. The subsea pig launcher shown in FIG. 2 requires an initial capital investment in the launcher, and also incurs high operating costs associated with bringing additional pigs to the launcher, i.e., with an ROV or a diver.
There is a need in the industry, especially in deepwater applications, to reduce the cost of the offshore development and production of hydrocarbons. Accordingly, what is needed is a piggable offshore system that eliminates the costs of additional equipment and/or maintenance. By reducing the expense of the installation and maintenance of additional risers, and eliminating the expense of the installation and maintenance of the subsea pig launcher while providing a piggable offshore hydrocarbon recovery system, the current invention satisfies this need.